This invention relates to rotary drill bits for drilling well bores in the earth for oil and gas production of the type used in conjunction with the drilling fluid circulation system of a rotary drill rig, and more particularly to nozzle assemblies for such drill bits for directing drilling fluid under pressure against the well bore bottom.
This invention involves an improvement over conventional nozzle assemblies of the type, such as shown for example in U.S. Pat. No. 4,381,825, which are secured in nozzle bores in the bottom of the body of a drill bit and are positioned closely adjacent to the well bore bottom when the drill bit is in the well bore in engagement with the well bore bottom. The bit body has an upper threaded pin adapted to be detachably secured to a drill string used to rotate the bit and a chamber therein in fluid communication with the passage in the drill string. The nozzle bores of the bit body are in fluid communication with the chamber and open to the exterior of the bit body. The drill bit, which is of the so-called "STRATAPAX" drag bit type, is used in conjunction with the drilling fluid circulation system of a rotary drill rig. In this system, drilling fluid under pressure is pumped down the drill string into the chamber in the bit body, with the drilling fluid exiting the bit via the nozzle bores and the nozzle assemblies. Upon exiting the bit, the drilling fluid returns back up to the drill rig via the annular space or annulus between the drill string and the wall of the well bore.
Each nozzle assembly comprises a nozzle member consisting of a cylindrical nozzle portion having passaging therein and a threaded sleeve brazed on the nozzle portion, and a retaining ring for securing the nozzle member in the nozzle bore. The cylindrical nozzle portion sealingly engages a seal member in the nozzle bore and the threaded sleeve is threaded in a threaded portion of the nozzle bore. The retaining ring is press-fit into the nozzle bore and engages the outer face of the nozzle member for preventing unintended rotation of the nozzle member which would cause the nozzle member to move out of the nozzle bore.
While the above-described nozzle assembly has proven to be generally satisfactory, it has a significant limitation; namely, it does not permit the nozzle orifice diameter to be changed. In drilling, the nozzle orifice diameter is preferably chosen so as to maximize the hydraulic cleaning action of the drilling fluid. More particularly, the drilling fluid flows from the nozzle assembly and impinges the well bore bottom at a relatively high velocity, and thus assists the drill bit in drilling the well bore bottom by lifting cuttings from the well bore bottom and flushing them up the annulus between the drill string and the wall of the well bore.
There are two widely accepted theories for maximizing the hydraulic cleaning action of the drilling fluid; namely, (1) deliver the maximum hydraulic horsepower power to the well bore bottom via the stream of drilling fluid exiting the nozzle assemblies, and (2) deliver the maximum hydraulic jet impact force to the well bore bottom. Under the first theory, the drilling fluid flows through the nozzle assembly at such a drilling fluid volume flow rate and fluid velocity that the stream impinges the well bore bottom with the highest energy level as measured in hydraulic horsepower. Under the second theory, the drilling fluid volume flow rate and fluid velocity are such that the stream impinges the well bore bottom with the highest possible impact force. Normally, the hydraulic pumps of the fluid circulation system of a drill rig are operated to deliver the maximum horsepower. Thus, the only variable affecting the drilling fluid flow rate and velocity (and thus its hydraulic energy or impact force), over which the rig operator has control is the nozzle orifice size of the nozzle assemblies. However, because of changes in factors such as drilling depth, the density of the drilling fluid, and the diameter of the drill string, the optimum nozzle orifice size may and often does vary as between the drill bits used in drilling a well bore. Indeed, the optimum nozzle orifice size for an individual bit may change during its use. Thus, to ensure that a drill bit has nozzle assemblies having the optimum nozzle orifice diameter installed therein, the nozzle assemblies must be capable of being installed in the drill bit just prior to its use and to be removed during non-drilling periods of its use, such as when the drill bit is pulled to enable well casing to be installed.
However, with the nozzle assemblies of U.S. Pat. No. 4,381,825, it is not possible to change the nozzle member and thus the nozzle orifice diameter once the retaining ring is pressed into the nozzle bore. Thus, it is not possible to change the orifice diameter during non-drilling periods in the use of this drill bit, nor if the bit is to be reused in drilling a second well bore requiring a different orifice diameter. Moreover, to enable nozzle assemblies having the optimum orifice diameter to be installed in the drill bit just prior to its use, a large inventory of nozzle members must be available at the drill rig. More particularly, there must be a plurality of sets of nozzle members, with each set including one nozzle member for each of the nozzle bores in the drill bit and with the nozzle members of each set having a nozzle orifice diameter different from those of the members of the other sets to provide members having all nozzle orifice diameters anticipated to be needed at the drill rig. Because this nozzle assembly is of unique construction, it cannot be used on drill bits of other types, such as roller cutter drill bits, which would enable the amount of inventory of the nozzle assemblies to be reduced.